The use of sodium hydrosulfide (NaSH) to separate copper and molybdenum was discovered and developed by Kerley Industries in the 1960's. Typically, NaSH has been used as a liquid solution containing 20%-45% NaSH in a liquid solution as a depressant and sulfidizing agent by the mineral recovery industry. Typical commercial high grade NaSH solutions are made by combining hydrogen sulfide with caustic soda as shown in the following reaction:H2S+NaOH→NaHS+H2O  (1)
Sodium hydrosulfide is a dangerous chemical and is also used in the pulp and paper industries, the leather-tanning industries and as a raw material or purifying agent in manufacturing.
It is well known that a number of processes used in refining petroleum produce water containing sulfur and nitrogen containing compounds. These waters are typically called sour water or foul water. Sour water producing processes include; for example, crude distillation, hydrotreating, catalytic cracking, thermal cracking, delayed coking and hydrocracking. Ammonia hydrosulfide or ammonia sulfide are usually present in sour water either because ammonia has been added to neutralize hydrogen sulfide or as a result of the hydrogenation of nitrogen during the refining process depending on the pH of the water and the amount of sulfur present. Typically, refinery sour water has a pH of 9.0 and ammonia hydrosulfide is present.
Because crude oil contains sulfur, modern oil refineries treat the sulfur containing fractions of crude oil with hydrogen in a process called hydrotreating and/or hydrocracking in order to meet the environmental standards of sulfur content of petroleum fuels. During the refining process, the sulfur and nitrogen in the crude oil is converted to hydrogen sulfide (a gas) and ammonia (a gas) that react with each other and form water soluble solids that must be washed out of all fractions of crude oil derivatives produced in a standard oil refinery. This washing of the crude oil products produces a high volume of sour water, foul smelling wash water typically containing 1%-2% ammonium hydrosulfide (NH4HS).
For reasons related in particular to the environment, the sour water containing ammonium hydrosulfide (NH4HS) cannot be released without further treatment. To reduce the disposal problem of the sour water and recover large amounts of water for further use as wash water the dilute “sour water” is stripped with heat. Generally the stripping process uses a hot gas stream that forces ammonium hydrosulfide (NH4HS) solution into the gas phase as hydrogen sulfide, ammonia and water for further treatment in a sulfur recovery unit such as a Claus unit. Typically the stripping process of refinery sour water streams uses steam to liberate more hydrogen sulfide but is complicated by the added presence of ammonia and other chemicals. A typical Sour Water Stripper Overhead Gas (“SWS Gas”) has a temperature of typically 185 to 200° F. and the approximate average analysis of 25% NH3, 49% H2S, and 26% H2O (water), weight %.
SWS Gas is a hazardous, deadly and dangerous to handle gas—it gives off a very deadly H2S gas vapor. Hydrogen Sulfide (H2S) is a very deadly gas and is produced in very large quantities today by the petroleum industry. However, due to the H2S being a deadly gas, and even though H2S is an unavoidable and unwanted by-product, and costly to get rid of, the H2S by-product producers are highly reluctant to depend on a third party to take responsibility of disposal due to handling and safety issues.
Information relevant to these issues can be found in the following U.S. Pat. Nos.: 2,761,755, 3,097,926, 3,761,409, 3,859,584, 3,909,422, 4,002,727, 4,060,594, 4,083,945, 4,315,903, 4,400,361, 4,451,442, 4,499,059, 5,993,667, 6,156,191 each of these US Patents are hereby incorporated herein by reference.
The practice in most oil refineries is to dispose of the SWS Gas as fast and as soon as it leaves the sour water stripper column. This is accomplished by feeding it, as produced, into a standard Claus Sulfur Recovery Unit (“SRU”) operating, at approximately 2,600° F., where it decomposes and transforms into elemental sulfur, and non-hazardous steam and nitrogen. A typical SRU costs approximately one hundred forty million dollars installed. While these costs are high, but generally accepted as the best available technology, due to environmental and safety concerns and the refiners need to dispose of the SWS Gas, producing other products from the SWS Gas is not currently thought of as an acceptable alternative.
Because ammonia gas is a valuable and basic ingredient in all plant food and because sulfides can be used in the mining and other industries, it would be highly advantageous to reclaim ammonia and other usable sulfide products from refinery waste streams such as sour water streams. Specifically, it would be also advantageous in the disposal and use of SWS Gas that the products produced therefrom find immediate, valuable use and are environmentally safe, as this invention allows. The hazardous nature of the SWS Gas is drastically reduced as soon as it enters the process covered by this invention and valuable ammonia is salvaged with the value adding to the economics of this process of producing high quality, high analyses NaHS.
The SWS Gas waste product that this invention removes from a modern petroleum refinery became a serious problem to the petroleum refiners approximately twenty (20) years ago as a result of the world's need to lower the sulfur content of petroleum products. In their attempt to comply with the lower sulfur specifications in their products, the industry has invested well into the billions of dollars in facilities and millions of dollars in operating costs to operate them. Not a single refinery has come up with the process, the subject of this invention, all the while choking over the problem. This is especially true of the mid-size to small refineries.